1. Field of the Invention
The present invention relates to the field of hydrocarbon recovery. More specifically, the present invention relates to the production of hydrocarbon fluids and the recovery of water-soluble minerals, such as nahcolite and/or soda ash, from an organic-rich rock formation, such as an oil shale formation.
2. Background of the Invention
Certain geological formations are known to contain an organic matter known as “kerogen.” Kerogen is a solid, carbonaceous material. When kerogen is imbedded in mineral formations, the mixture may be referred to as oil shale. This is true whether or not the mineral is, in fact, technically shale, that is, a rock formed from compacted clay. Upon heating, kerogen produces oil, gas and some water. Oil shale formations are typically found at relatively shallow depths (<about 3,000 feet) in various areas world-wide and of the United States, including for example Wyoming, Colorado and Utah. Many such formations are known to have extremely limited permeability.
Kerogen may be converted to mobile hydrocarbons by heating the oil shale to temperatures generally in excess of 270° C. (518° F.). The rate of conversion increases sharply with increasing temperature. When kerogen is heated, chemical reactions break the larger molecules forming the solid kerogen into smaller molecules of oil and gas. The thermal conversion process is referred to as pyrolysis or retorting.
Attempts have been made for many years to extract oil from oil shale formations. Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales. The industry lasted for about 100 years. Commercial oil shale retorting has also been conducted in other countries such as Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomical or because of environmental constraints on spent shale disposal. (T. F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p. 292). The entire disclosure of which is incorporated herein by reference. Further, surface retorting requires mining of the oil shale, which limits application to shallow formations.
Research on oil shale production was generally carried out through the 1900's. In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom, the entire disclosure of which is incorporated herein by reference. That patent, entitled “Method of Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” proposed the application of heat at high temperatures to the oil shale formation in situ. Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilled into the formation. The bore holes received an electrical heat conductor which transferred heat to the surrounding oil shale. Thus, the heat supply channels served as heat injection wells.
The heat injection wells were equipped with electrical heating elements. The elements, in turn, were surrounded by sand or cement or other heat-conductive material. Each heat injection well transmitted heat into the surrounding oil shale while preventing any inflow of fluid. Along with the heat injection wells, fluid producing wells were also completed in near proximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into the rock matrix, the resulting oil and gas would be recovered through the adjacent production wells.
Ljungstrom applied his approach of thermal conduction from heated wellbores through the Swedish Shale Oil Company. A full-scale plant was developed that operated from 1944 into the 1950's. (G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2nd Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951)). The entire disclosure of which is incorporated herein by reference.
Since 1947, various patents have been issued offering modifications and improvements to Ljungstrom's ideas. For instance, U.S. Pat. No. 3,468,376 issued to Slusser, et al. in 1969 entitled “Thermal Conversion of Oil Shale into Recoverable Hydrocarbons”, the entire disclosure of which is incorporated herein by reference. The '376 Slusser, et al. patent suggested a process for circulating a heated pyrolyzing fluid through a flow channel. Abrasive particles were added to the circulating fluid to erode a layer of pyrolyzed oil shale being formed adjacent to the flow channel. This provided a channel for the flow of converted kerogen.
It was recognized in the Slusser, et al. patent that “[t]here are two mechanisms involved in the transport of heat through the oil shale.” First, heat is transferred through the solid mass of oil shale by conduction. Second, heat is transferred by convection through fluid flow of pyrolyzed kerogen within the oil shale.” Slusser, et al. noted that typically the transfer of heat by conduction is a relatively slow process due to the oil shale being an inherently poor conductor of heat. If significant permeability does exist or is created, convective heat transfer by fluids traveling through fine channels in the oil shale can contribute to the overall rate of heat transfer.
Various means for heating the rock matrix and imbedded kerogen have been proposed. U.S. Pat. No. 4,140,180, assigned to the ITT Research Institute in Chicago, Ill. and issued in 1979, suggested the application of in situ heat using radio frequency (RF) electrical energy. The entire disclosure of which is incorporated herein by reference. In doing so, the '180 patent listed and described other methodologies for applying pyrolyzing heat using electrical energy. The patent stated that, as of that time, “there is no . . . acceptable economical way to extract the hydrocarbon constituents.”
Techniques for in situ retorting of oil shale were developed and pilot tested with the Green River oil shale in the United States in the 1970's and 1980's. In situ processing offers advantages because it reduces costs associated with material handling and disposal of spent shale. In a number of the in situ pilots, the oil shale was first rubblized. Thereafter, combustion was carried out by air injection. A rubble bed with substantially uniform fragment size and substantially uniform distribution of void volume was a key success factor in combustion sweep efficiency. Fragment size was of the order of several inches.
Nevertheless, attempts to economically extract shale oil continued. In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entire disclosure of which is incorporated herein by reference. That patent, entitled “Conductively Heating a Subterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that “[c]ontrary to the implications of . . . prior teachings and beliefs . . . the presently described conductive heating process is economically feasible for use even in a substantially impermeable subterranean oil shale.” (col. 6, ln. 50-54). The '118 patent proposed controlling the rate of heat conduction within the rock surrounding each heat injection well to provide a uniform heat front. The process was limited to formations having a specified grade and thickness.
Additional history behind shale oil retorting and recovery can be found in patent publication WO 2005/010320 entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons,” and in WO 2005/045192 entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” The Background and technical disclosures of these two patent publications are incorporated herein by reference.
The WO 2005/010320 process involves the use of electrically conductive fractures to heat the oil shale. A heat source is constructed using wellbores and then hydraulically fracturing the oil shale. The fractures are filled with an electrically conductive material which forms a heating element. Calcined petroleum coke is a suitable conductant material. Preferably, the fractures are created in a vertical orientation along longitudinal, horizontal planes formed by horizontal wellbores. Electricity is conducted through the conductive fractures from the heel to the toe of each well. The electrical circuit is completed by an additional horizontal well that intersects one or more of the vertical fractures near the toe to supply the opposite polarity. Modeling suggests that temperatures in the immediate vicinity of the fracture exceed 600° C. Thermal conduction heats and artificially matures the oil shale to conversion temperatures in excess of 300° C.
The WO 2005/045192 process involves the circulation of supercritical naphtha through fractures. This means that the oil shale is heated by circulating a dense, hot hydrocarbon vapor through sets of closely-spaced hydraulic fractures. In this instance, the fractures are horizontally formed and conventionally propped. Fracture temperatures of 320°-400° C. are maintained for five to ten years. Vaporized naphtha is typically the preferred heating medium due to its high volumetric heat capacity, ready availability and relatively low degradation rate at the heating temperature. In the WO 2005/045192 process, as the kerogen matures, fluid pressure will drive the generated oil to the heated fractures, where it will be produced with the cycling hydrocarbon vapor.
In some oil shale formations, additional minerals of commercial value are present within the rock. One such mineral is nahcolite. Nahcolite is a natural mineral (NaHCO3), and is commonly known as baking soda or sodium bicarbonate. The mineral can be associated with oil shale deposits such as those located in parts of the Piceance Basin in Colorado. Nahcolite resources in the Piceance Basin are estimated by the United States Geological Survey at over 29 billion metric tons. (J. R. Dyni, “Stratigraphy and Nahcolite Resources of the Saline Facies of the Green River Formation in Northwest Colorado,” in D. K. Murray (ed.), Guidebook to the Energy Resources of the Piceance Creek Basin Colorado, Rocky Mountain Association of Geologists—1974 Guidebook, pp. 111-122 (1974)). The entire disclosure of which is incorporated herein by reference.
Nahcolite typically occurs as finely disseminated crystals and nodules within oil shale beds. It also occurs in several discrete beds mixed with variable amounts of oil shale and sometimes associated with halite. Much of the nahcolite in the Piceance Basin occurs as either non-bedded crystalline aggregates scattered through the oil shale, or as laterally continuous units of fine crystals disseminated in the oil shale. The sodium bicarbonate processed from nahcolite has value for use in food (as baking soda), in pharmaceutical products, in flue gas clean-up (such as SO2 removal), and in fire extinguishers.
Sodium bicarbonate can be converted to sodium carbonate (Na2CO3; also known as soda ash). The conversion takes place in the presence of heat according to the following chemical reaction:2NaHCO3Na2CO3+CO2+H2OSodium carbonate, or soda ash, is a large-scale commodity chemical. Soda ash is used in glass making, chemical manufacture, and the manufacture of detergents. Much of the sodium bicarbonate produced via mining is converted in surface facilities to soda ash.
Nahcolite can be recovered from oil shale via solution mining. (M. Prats, P. J. Closmann, A. T. Ireson, and G. Drinkard, “Soluble-Salt Processes for In-Situ Recovery of Hydrocarbons from Oil Shale,” Journal of Petroleum Technology, pp. 1078-1088 (September 1977)). The entire disclosure of which is incorporated herein by reference. The process involves injecting hot water under pressure into the subsurface. Sodium bicarbonate is fairly soluble in water.
American Soda previously developed a facility in the Piceance region of Colorado for solution mining of Nahcolite. The facility was operational in 2000. American Soda's production operations are described in the 2004 publication M. Ramey and M. Hardy, “The History and Performance of Vertical Well Solution Mining of Nahcolite (NaHCO3) in the Piceance Basin, Northwestern, Colorado, USA”, Solution Mining Research Institute: Fall 2004 Technical Meeting (Berlin, Germany) (2004). The entire disclosure of which is incorporated herein by reference. American Soda's solution mining technology is also discussed in U.S. Pat. No. 6,609,761 issued in 2003. The entire disclosure of which is incorporated herein by reference. According to the paper, the well field included 26 solution mining wells which produced nahcolite brine to a processing facility. Water at 350-420° F. was injected into the formation to remove the nahcolite at a depth of 2,200 to 2,600 feet.
By late 2004, the American Soda facility had produced 2.6 million tons of nahcolite. The facility converted the sodium bicarbonate to sodium carbonate, produced liquid CO2, and concentrated the sodium carbonate solution via evaporation. The solution was then pumped to a second facility 44 miles away. The conversion of sodium bicarbonate to sodium carbonate was necessary to prevent solid precipitation in the pipeline as the solution cooled during transit. Sodium carbonate is much more soluble than sodium bicarbonate at the flow temperatures. The solution at the second facility was then reconverted back to sodium bicarbonate via contacting the solution with CO2 to precipitate the sodium bicarbonate. The sodium bicarbonate was then sold and shipped from the facility.
Other companies such as White River Nahcolite Minerals and American Alkali have studied Nahcolite solution mining and processing. (R. L. Day, “Solution Mining of Colorado Nahcolite,” Wyoming State Geological Survey Public Information Circular 40, Proceedings of the First International Soda Ash Conference, Volume II (Rock Springs, Wyo., Jun. 10-12, 1997) pp. 121-130 (1998); K. R. Nielsen, “Colorado Nahcolite: A Low Cost Source of Sodium Chemicals,” Seventh Annual Canadian Conference on Markets for Industrial Minerals (Vancouver, Canada, Oct. 17-18, 1995) 1-9). The entire disclosures of which are incorporated herein by reference. In the disclosed processes, the produced sodium bicarbonate solution is processed through a facility in order to generate three dry products: sodium bicarbonate, light soda ash, and dense soda ash. The processes start by crystallizing sodium bicarbonate out of solution via cooling. Light soda ash is produced by drying wet sodium bicarbonate at 600-800° F. This results in decomposition to a low bulk density (30-35 lbs/ft3) powder. Dense soda ash is formed by crystallizing soda ash out of a supersaturated solution. This results in granules with a bulk density of about 63 lbs/ft3. The benefit of producing three products is that each has a different market. The facility can shift the distribution of products based on current market conditions. Typically, sodium bicarbonate and light soda ash command higher prices, but the markets are more limited than for dense soda ash.
Another company involved in Nahcolite mining operations is NaTec, Ltd. NaTec is the listed assignee of U.S. Pat. No. 4,815,790 which issued in 1989, the entire disclosure of which is incorporated herein by reference. The patent is entitled “Nahcolite Solution Mining Process.” The patent discloses a process for creating sodium bicarbonate using a “hot aqueous liquor.” This process also produced sodium bicarbonate solution which was then processed through a facility to generate three dry products: sodium bicarbonate, light soda ash, and dense soda ash. It is noted that much of the nahcolite was converted to a soda ash product at the surface facilities.
Because nahcolite and oil shale occur together in certain oil shale deposits such as the Piceance Basin, the recovery of either mineral impacts the fate of the other. It has been proposed that nahcolite can be removed through solution mining prior to the in situ production of shale oil. This was discussed by Prats, M., et al. in the 1977 articled cited above. This was also proposed by Shell as early as 1972 in U.S. Pat. No. 3,700,280, entitled “Method of Producing Oil from an Oil Shale Formation Containing Nahcolite and Dawsonite”, the entire disclosure of which is incorporated herein by reference. See also U.S. Pat. No. 3,759,574 entitled “Method of Producing Hydrocarbons from an Oil Shale Formation”, the entire disclosure of which is incorporated herein by reference. The concept of nahcolite removal involves leaching the nahcolite (and other water-soluble minerals such as halite and, to a lesser degree, dawsonite) to create permeability in the otherwise fairly impermeable oil shale. After the permeability is created, hot steam is injected into the formation to convert the kerogen bound in the oil shale to liquid (oil) and hydrocarbon gas. The oil and gas is then recovered via production wells.
Recently, U.S. Pat. No. 6,997,518 issued to Vinegar, et al. in 2006, the entire disclosure of which is incorporated herein by reference. This patent is entitled “In Situ Thermal Processing and Solution Mining of an Oil Shale Formation.” The '518 patent proposes developing nahcolite prior to in situ conversion of the oil shale using downhole heat sources. Such heat sources include electric heaters and downhole flameless combustors. Vinegar argues that removing the nahcolite prior to shale oil production is beneficial since it reduces the energy needed to convert the kerogen. The decomposition reaction of nahcolite is endothermic plus the nahcolite has thermal capacity and, hence, drains energy otherwise useable for heating the oil shale. Additionally, in certain areas regulatory conditions require that the oil shale be developed in such a way as to preserve the value of the nahcolite.
The '518 patent lists a variety of other perceived advantages to removing nahcolite (and dawsonite) prior to kerogen retorting. For instance, Vinegar states that removing the nahcolite “may reduce mass within the formation and increase a permeability of the formation. Reducing the mass within the formation may reduce the heat required to heat to temperatures needed for the in situ conversion process. Reducing the mass within the formation may also increase a speed at which a heat front within the formation moves. Increasing the speed of the heat front may reduce a time needed for production to begin.” (See col. 324, ln. 40-48).
A need exists for improved processes for the production of shale oil which preserves the value of the nahcolite in-place. In addition, a need exists for improved methods for co-developing shale oil and nahcolite in soda ash form. Still further, a need exists for a process by which the nahcolite may be recovered after heating an oil shale zone and producing the shale oil.